Oil and gas wells may be several thousand feet deep and may pass through several different hydrocarbon producing formations. Additionally, fresh water formations may be traversed by the wellbore. It is important in the completion of such a well that each producing formation be isolated from all other producing formations and from fresh water formations and the surface. The need for zonal isolation also arises in other types of wells such as, for example, water source wells, storage wells, geothermal wells and injection wells. Typically, this isolation is accomplished by installing metallic tubulars in the wellbore which are joined by threaded connections and cemented in place. These metallic tubulars are typically referred to as "casing". The term "liner" is also used to refer to a string of casing whose top is located below the surface of the well. All such metallic tubulars will be referred to herein as "casing".
The process for primary cementing of a metallic casing is well known. During drilling operations the wellbore is filled with a drilling fluid. The hydrostatic pressure exerted by the drilling fluid on the walls of the wellbore prevents flow of formation fluids into the wellbore. After the well has been drilled to the desired depth the casing is inserted into the wellbore and a cement slurry is pumped down the casing and up the annular space between the casing and the wall of the wellbore thereby displacing the drilling fluid. If the cement extends to the surface all of the drilling fluid is normally displaced, except any which may be by-passed in a filter cake on the wall of the wellbore. Alternatively, if the cement does not extend to the surface some drilling fluid will remain in the annulus above the cement. Upon completion of the displacement process the combined hydrostatic pressure exerted by the drilling fluid, if any, and the cement slurry prevents formation fluids from entering the wellbore. When the cement cures, each producing formation should be permanently isolated thereby preventing fluid communication from one formation to another. The cemented casing may then be selectively perforated so as to produce fluids from a particular formation.
Unfortunately, however, a large percentage of well completions are unsuccessful or, at best, only partially successful in achieving total zonal isolation of the various producing formations penetrated by the well. This is especially true in deep well completions across relatively high pressure gas producing formations where gas flow to the surface through the cemented annulus is often observed soon after completion of the cementing. This phenomenon, known as annular fluid flow, is a major problem requiring expensive and technically difficult remedial measures. One such remedial measure is described in U.S. Pat. No. 4,074,756 to Cooke, Jr., issued Feb. 21, 1978. The term "annular gas flow" is also used in the literature to describe this problem. However, since the problem may occur with liquids as well as gases, the term "annular fluid flow" is more accurate.
Another example of annular fluid flow is observed when wells are drilled in areas where secondary or tertiary oil recovery operations are in progress. Such operations typically involve the injection of a fluid such as, for example, water, carbon dioxide, surfactants or methane so as to force the oil to flow toward the recovery wells. A new well in such an area may penetrate zones of widely different permeability and pressure. Flow of the injected fluids behind the well casing, caused by lack of zonal isolation, is a major problem in these areas. Although such flow usually does not occur to the surface, flow between subterranean formations is often found.
The problem of annular fluid flow was first recognized in the mid 1960's. See, for example, Carter G. and Slagle K., "A Study of Completion Practices to Minimize Gas Communication", Paper SPE 3164, presented at the Central Plains Regional Meeting of the Society of Petroleum Engineers of AIME held in Amarillo, Texas, Nov. 16-17, 1970. A great deal of time and effort has been expended seeking a solution to this long-standing problem. No completely satisfactory solution has yet been proposed.
The failure mechanism which results in annular fluid flow is probably very complex with a number of different factors combining to produce the failure. Several different theories have been advanced to explain annular fluid flow, and a number of potential solutions have been proposed. One theory suggests that annular fluid flow occurs when the cement slurry fails to uniformly displace the drilling fluid from all parts of the annulus. This results in the presence of longitudinal channels of gelled drilling fluid in or next to the cement sheath which provide paths for fluid communication between the various formations penetrated by the well. One proposed solution for this problem is the use of pipe movement during the displacement process. Pursuant to this solution scratchers are attached to the outside of the casing being cemented and the casing is slowly raised and lowered while the cement is being pumped into the annulus. Typically, the casing is moved vertically for a distance of several feet with movements of up to 30 feet being common. The movement of the scratchers helps to dislodge any gelled drilling fluid which may be adhering to the wall of the wellbore thereby facilitating total displacement of the drilling fluid by the cement slurry. See, for example, "Recommended Procedure For the Use of Reversible Scratchers and Spiral Centralizers", Weatherford Oil Tool Co., Inc., Technical Bulletin published in the Journal of Petroleum Technology, September, 1956. Typically, the pipe movement is terminated upon completion of the displacement process and the cement slurry is allowed to harden undisturbed. In some cases the pipe movement may be continued for a few minutes after completion of the displacement process so as to mix any remaining drilling fluid into the cement slurry. Such movement must be terminated when increased drag on the pipe indicates that the cement has begun to thicken.
A second theory suggests that annular fluid flow occurs due to a reduction in the hydrostatic pressure exerted by the cement column during its initial hydration period. During pumping the cement slurry behaves as a liquid and fully transmits hydrostatic pressure. Thus, immediately after the cement is pumped into the annulus the hydrostatic pressure in the cement column is typically considerably greater than the pressure of the fluids in the various producing formations. If, however, the hydrostatic pressure of the cement column drops below the pressure of the formation fluids, the fluids will flow into the cemented annulus creating channels which permit communication between the various formations. Under this theory the reduction in hydrostatic pressure is attributed to a variety of factors such as excessive cement dehydration, cement shrinkage and nonuniform cement hydration. See, Levine, D. C., et al., "Annular Gas Flow After Cementing: A Look at Practical Solutions", Paper SPE 8255, presented at the 54th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME held in Las Vegas, Neveda, Sept. 23-26, 1979. Levine, et al., propose the use of techniques such as adjusting the height of the cement column, varying the thickening time of the cement slurry, applying surface pressure to the cemented annulus, increasing the drilling fluid density, increasing the mix water density, utilizing multiple stage cementing procedures and utilizing modified cement slurries. Each of these proposed techniques is applicable only in certain specific situations and it is difficult to predict the results for a specific application. Use of such techniques may be of some help; however, they do not provide an adequate solution to the problem.
Another explanation for the reduction in hydrostatic pressure is discussed in U.S. Pat. No. 4,120,360 to Messenger, issued Oct. 17, 1978. Messenger contends that the reduction in hydrostatic pressure results from a separation of the cement slurry into water and discrete particles of cement, which particles then form a cement lattice and prevent the full hydrostatic pressure of the cement slurry from being transmitted down the annulus. Messenger proposes the use of a lightweight thixotropic cement slurry that has zero water separation to solve the problem of annular fluid flow.
Still another explanation for the reduction in hydrostatic pressure is presented in Davies, D. R., et al., "An Integrated Approach for Successful Primary Cementations", Paper SPE 9599, presented at the Middle East Oil Technical Conference of the Society of Petroleum Engineers held in Manama, Bahrain, Mar. 9-12, 1981. Davies, et al., suggest that hydrostatic pressure is lost due to a build-up of gel strength coupled with a simultaneous volume reduction caused by the cement hydration process and by fluid loss to permeable formations. Davies, et al., propose an integrated, total job design approach to primary cementing to solve the problem of annular fluid flow. This integrated approach involves the use of improved drilling practices, improved displacement procedures and a highly dilatant, thinned scavenger cement slurry to achieve good drilling fluid displacement.
Yet another proposed solution is discussed in Tinsley, J. M., et al., "Study of Factors Causing Annular Gas Flow Following Primary Cementing", Paper SPE 8257, presented at the 54th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME held in Las Vegas, Nevada, Sept. 23-26, 1979. Tinsley, et al., propose the use of a new, compressible cement system to solve the problem of annular fluid flow. The cement's compressibility and volume are increased by introducing a gaseous phase into a conventional cement slurry in the form of small, finely dispersed bubbles. The bubbles are generated by a chemical reaction in the cement. Field application of this proposed solution, however, requires a great deal more engineering design than conventional cementing systems. The amount of gas necessary to increase the cement's compressibility and volume must be calculated for each specific application and the rate of the chemical reaction which forms the bubbles must be controlled very carefully.
As stated above, pursuant to the present invention the casing is vibrated after the cement has been introduced into the annulus so as to maintain the hydrostatic pressure of the cement column above the pressure of the fluids in the formations penetrated by the well. Vibration has been used in the past for a variety of oil well related purposes. See, for example, U.S. Pat. No. 3,557,875 to Solum, et al., issued Jan. 26, 1971, which discloses the use of vibration to aid in the displacement process during primary cementing of casings. Pursuant to this process, the casing is vibrated while the cement is being pumped into the well so as to dislodge any gelled drilling fluid which may be adhering to the wall of the wellbore. Vibration is terminated upon completion of the displacement process and the cement is allowed to harden undisturbed. A second use for vibration is disclosed in U.S. Pat. No. 3,239,005 to Bodine, Jr., issued Mar. 8, 1966. Bodine uses resonant vibration to break the bond between a cement sheath and a smooth metallic mandrel inserted into the wellbore so that the mandrel can be removed after the cement has cured leaving only the cement sheath in the well. Thus, Bodine is not applicable to installation of standard metallic casings which utilize centralizers and scratchers attached to the outside of the casing and which have pipe collars on their ends for joining several sections together. These protuberances would prevent removal of the casing after the cement has cured. Additionally, Bodine is applicable only to relatively shallow wells. Oil and gas wells may be drilled to depths of 2 miles or more. Such wells are not vertically straight. Horizontal deviations of 100 feet or more from the projected centerline are common. In fact, some wells are intentionally deviated from vertical using known techniques for directional drilling. These horizontal deviations would prevent removal of the rigid mandrel disclosed by Bodine. Also, the surface vibrations of Bodine would be totally damped out within a few hundred feet of the surface leaving the majority of the cemented annulus undisturbed. Neither Solum et al. nor Bodine teach that vibration may be used to maintain the hydrostatic pressure in a cement column as it cures.
It is obvious from the foregoing that annular fluid flow is a significant, long-standing problem which, as yet, is not well understood. A great deal of time and effort has been expended seeking a solution to this problem. Several theories and possible solutions have been proposed. However, none of the proposed solutions is wholly satisfactory. Clearly, the need exists for a reliable, easy to use method for effectively preventing annular fluid flow following primary cementing of well casings.